The term fracturing fluid refers to fluids utilized for injection at high pressure into oil or gas wells, to fracture the geological formations surrounding the wells, and thereby increase the porosity of same. This permits more efficient flow of hydrocarbons in the formation and thereby increases the productivity of the well.
The primary function of a fracturing fluid is two-fold: first to transmit energy generated at surface down a well bore to hydraulically create a fracture within reservoir rock, and secondly, to transport a propping agent (usually sand) from surface to the reservoir to ensure conductivity generated by the fracture is preserved. Since this process involves the introduction of a foreign fluid into the porosity of the reservoir near the fracture face, removal of the fluid can be a critical component to the success of the treatment. Once the fluid is removed, or its effects minimized, a successful stimulation has a pipeline placed connecting the reservoir to the well bore and increased the productive economics of the well.
A hydraulic fracturing treatment consists of three main stages. Initially a “Hole Fill/Pad” stage is pumped to initiate the fracture and create width for the stages to follow. It consists of water treated with a viscosifier and a breaker added at various concentrations, depending primarily on the temperature of the reservoir to be fractured. After a sufficient volume of Pad has been pumped (typically 10-40 m3), proppant is added to the fluid stream to form the “Slurry” stage. Concentrations of the proppant (sand, resin-coated sand, or ceramics) are kept low at the beginning and slowly ramped up to maximum values, which vary as a function of depth, fracturing pressures, and reservoir type. An optimization process utilizing numerical and analytical simulation models determines the amount of proppant that is pumped. Once the appropriate volume of proppant has been mixed by the blender and pumped down the well bore, a “Flush” stage consisting of water, sometimes with viscosifier and breaker, is used to displace the “Slurry” stage to the perforations.
Treatment design is based on several parameters that include, but are not limited to, reservoir permeability, pressure, depth, temperature and reservoir fluid type. Fracture fluid viscosity, down-hole injection rate, proppant size and type, proppant volume and concentration are all important aspects of the final stimulation program. Engineering modeling tools, together with previous field experience gained in each area are used in a combined approach to formulate the best possible stimulation design for the reservoir.
A desirable feature in a fracturing fluid is variable viscosity. That is, fluids will frequently contain additives that can be selectively altered, chemically or physically, to increase or decreases the viscosity of the fluid. The reason a high viscosity is desired is for the transport of proppant, such as sand granules into a fractured formation to prevent cracks and pores made by the fracturing process in the formation from closing. However, after that process is complete, it is desirable to lower the viscosity of the fluid, so that it can be pumped back out of the well without carrying the proppant granules with it.
A typical fracturing fluid will contain, for instance, guar with an average molecular weight of 2,000,000, which can be rapidly cross-linked by the addition of an activator such as a metal borate and broken by the use of an oxidizer such as a persulfate or peroxide.
A potential drawback of viscosification systems involving covalent chemical bonds is that the reactions involved in breaking the gel have thermal consequences, which are often not desirable. Moreover, such reactions are influenced by prevailing thermal conditions.